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Today (2011), the leading in situ EOR process to recover bitumen from oil sands reservoirs, such as found in the Athabasca region of Alberta in Canada, is SAGD (steam assisted gravity drainage). Bitumen is a very heavy type of oil that is essentially immobile at reservoir conditions, so it is difficult to recover. In situ combustion (ISC) is an alternative process that, so far, has shown little application for bitumen recovery.
SAGDOX (SAGD with oxygen) is another alternative process, for bitumen EOR that can be considered as a hybrid process combining the attributes of SAGD (steam) and ISC (oxygen). SAGDOX uses a modified SAGD geometry with extra wells or segregated injector systems to allow for separate continuous injection of oxygen and steam and removal on non-condensable gases produced by combustion.
1. Prior Art Review—Bitumen EOR
2.1 SAGD
In the early days of steam EOR, the focus was on heavy oil (not bitumen) and two process types, using vertical well geometry—steam floods (SF), where a steam injector would heat and drive oil to a producer well (California heavy oil EOR used this process) and cyclic steam simulation (CCS); where, using a single vertical well, steam was injected, often at pressures that fractured the reservoir. This was followed by a soak period to allow oil time to be heated by conduction and then a production cycle (Cold Lake, Alberta oil is recovered using this process).
But, compared to these processes and heavy oil, bitumen causes some difficulties. At reservoir conditions, bitumen viscosity is large (>100,000 cp.), bitumen will not flow and gas/steam injectivity is very poor or near zero. Vertical well geometry will not easily work for bitumen EOR. We need a new geometry with short paths for bitumen recovery and a method to start-up the process so we can inject steam to heat bitumen.
In the 1970-1980's using new technology to directionally drill wells and position the wells accurately, it became possible to drill horizontal wells for short-path geometry. Also, in the early 1970's, Dr. Roger Butler invented the SAGD process, using horizontal wells to recover bitumen (Butler (1991)). FIG. 1 shows the basic SAGD geometry using twin parallel horizontal wells with a separation of about 5 m, with the lower horizontal well near the reservoir bottom (about 2 to 8 m. above the floor), and with a pattern length of about 500 to 1000 m. The SAGD process is started by circulating steam until the horizontal well pair can communicate and form a steam (gas) chamber containing both wells. FIG. 17 shows how the process works. Steam is injected through the upper horizontal well and rises into the steam chamber. The steam condenses at/near the cool chamber walls (the bitumen interface) and releases latent heat to the bitumen and the matrix rock. Hot bitumen and condensed steam drain by gravity to the lower horizontal production well and are pumped (or conveyed) to the surface. FIG. 18 shows how SAGD matures—A young steam chamber has oil drainage from steep sides and from the chamber top. When the chamber grows and hits the ceiling (top of the net pay zone), drainage from the chamber top ceases and the sides become flatter, so bitumen drainage slows down.
Steam injection (i.e. energy injection) is controlled by pressure targets, but there also may be a hydraulic limit. The steam/water interface is controlled to be between the steam injector and the horizontal production well. But when fluids move along the production well there is a natural pressure drop that will tilt the water/steam interface (FIG. 13). If the interface floods the steam injector, we reduce the effective length. If the interface hits the producer, we short circuit the process and produce some live steam, reducing process efficiency. With typical tubulars/pipes, this can limit well lengths to about 1000 m.
SAGD has another interesting feature. Because it is a saturated-steam process and only latent heat contributes directly to bitumen heating, if pressure is raised (higher than native reservoir pressure) the temperature of saturated-steam is also increased, Bitumen can be heated to a higher temperature, viscosity reduced and productivity increased. But, at higher pressures, the latent heat content of steam is reduced, so energy efficiency is reduced (SOR increases). This is a trade off. But, productivity dominates the economics, so most producers try to run at the highest feasible pressures.
For bitumen SAGD, we expect recoveries of about 50 to 70% OBIP and the residual bitumen in the steam-swept chamber to be about 10 to 20% of the pore volume, depending on steam temperatures (FIG. 19). Since about 1990, SAGD has now become the dominant in situ process to recover Canadian bitumen and the production growth is exponential (FIG. 20). Canada has now exceeded USA EOR steam heavy oil production and it is the world leader.
The current SAGD process is still similar to the original concept, but there are still expectations of future improvements (FIG. 21). The improvements are focused on 2areas—using steam additives (solvents or non-condensable gases) e.g. Gates (2005) or improvements/alterations in SAGD geometry (Sullivan (2010), Kjorholt (2010), Gates (2010)).
2.2 In Situ Combustion (ISC)
In situ combustion (ISC) started with field trials in the 1950's (Ramey (1970)). ISC was the “holy grail” of EOR, because it was potentially the low-cost process. Early applications were for medium and heavy oils (not bitumen), where the oil had some in situ mobility. A simple vertical well was used to inject compressed air that would “push” out heated oil toward a vertical production well. The first version of ISC was dry combustion using only compressed air as an injectant (Gates (1977)) (FIG. 24). A combustion-swept zone is behind the combustion front. Downstream of the combustion front, in order, is a vaporizing zone with oil distillate and superheated steam, a condensing zone where oil and steam condense and an oil bank that is “pushed” by the injectant gas toward a vertical production well. The vaporizing zone fractionates oil and pyrolyzes the residue to produce a “coke” that is consumed as the combustion fuel.
Another version of ISC also emerged, called wet combustion or COFCAW. After a period of dry combustion, liquid water was injected with compressed air (or alternating injection). The idea was that water would capture heat inventoried in the combustion-swept zone to produce steam prior to the combustion front. This would improve productivity and efficiency (Dietz (1968), Parrish (1969), Craig (1974)). FIG. 31 shows how wet combustion worked, using the same simple vertical well geometry as dry combustion. A liquid water zone precedes the combustion-swept zone, otherwise the mechanisms are similar to dry ISC as shown in FIG. 24. The operator of a wet combustion process has to be careful not to inject water too early in the process or not to inject too much water, or the water zone can overtake the combustion front and quench HTO combustion.
The principles of dry and wet ISC were well known in the early days (Doschner (1966), Ramey (1970), Chu (1977)). The mechanisms were well documented. It was also recognized that these were two kinds of in situ combustion—low temperature oxidation (LTO), from about 150 to 300° C., where oxidation is incomplete, some oxygen can break through to the production well, organic compounds containing oxygen are formed, acids and emulsions are produced and the heat release per unit oxygen injected is lower; and high temperature oxidation (HTO), from about 400 to 800° C. where most (all) oxygen is consumed to produce combustion gases (CO2, CO, H2O . . . ) and the heat release per unit oxygen consumed is maximized. It was generally agreed that HTO was desirable and LTO was undesirable (Butler (1991)). [For Athabasca bitumen, LTO is from 150 to 300° C. and HTO is from 380 to 800° C. (Yang (2009(2))]. A screening guide for ISC (Chu(1977)) (φ>0.22, SO>50%, φSO>0.13, API<24, μ<1000 cp.) indicates that ISC, using vertical-well geometry, is best applied to heavy or medium oils, not bitumen.
Despite decades of field project trials, ISC has only seen limited success, for a variety of reasons. In a 1999 DOE review (Sarathi (1999)), more than half of the North American field tests of ISC were deemed “failures”. By the turn of the century the total world ISC projects dropped to 28 (Table 12).
ISC using oxygen or enriched air (ISC(O2)) was attempted in a few field projects. In the 1980's “hey day” for EOR, there were 10 ISC(O2) projects active in North America—4 in the USA and 6 in Canada (Sarathi (1999)). The advantages of using oxygen were purported as higher energy injectivity, production of near-pure CO2 gas as a product of combustion, some CO2 solubility in oil to reduce viscosity, sequestration of some CO2, improved combustion efficiency, better sweep efficiency and reduced GOR for produced oil. The purported disadvantages of using oxygen were safety, corrosion, higher capital costs and LTO risks (Sarathi (1999), Butler (1991)).
Only a few tests of ISC were undertaken for bitumen recovery using vertical well geometries. For a true bitumen (>100,000 c.p in situ viscosity) gas injectivity (air or oxygen) is very poor. So, even though bitumen is very reactive and has lower HTO and LTO temperatures than other oils and HTO can be sustained at very low oxygen/air flux rates (FIG. 25), bitumen ISC EOR processes are very difficult. New well geometries using horizontal wells, with short paths for bitumen recovery and perhaps a gravity drainage recovery mechanism, can improve the prospects for bitumen ISC EOR.
One such process that is currently field testing is the THAI process using a horizontal production well and horizontal or vertical air injector wells (FIG. 22, Graves (1996), Petrobank (2009)). So far, success has been only limited. Another geometry is shown in FIG. 23 for the COSH or COGD process (New Tech. Magazine (2009)).
Others (Moore 1999, Javad (2001), Belgrave (2007)) have proposed to conduct bitumen ISC in the steam-swept gravity drainage chamber produced by a SAGD process, using the residual bitumen in the steam-swept zone as ISC fuel after the SAGD process has matured or reached its economic limit. These studies have concluded that ISC is feasible for these conditions.
2.3 Steam+Oxygen
It may be considered that COFCAW (water+air/oxygen injection for ISC) may be similar to steam+oxygen processes. ISC using COFCAW and air or oxygen could create steam+oxygen or steam+CO2 mixtures when water was vaporized in the combustion-swept zone prior to (or after) the combustion front. But, if we have a modern geometry suited to bitumen recovery, we have short paths between wells. If liquid water is injected we would have a serious risk of quenching HTO reactions. COFCAW works for vertical well geometries (eg. Parrish (1969)) because of the long distance between injector and producer and the ability to segregate liquid water from the combustion zone until it is vaporized.
There is not much literature on steam+oxygen, but steam+CO2 has been considered for EOR for some time. Assuming we have good HTO combustion, a steam+oxygen mixture will produce a steam+CO2 mixture in the reservoir. Also, there has been some focus to produce steam+oxygen or steam+flue gas mixtures using surface or down hole equipment (Balog (1982), Wylie (2010), Anderson (2010)). Carbon dioxide can improve steam-only processes by providing other mechanisms for recovery—e.g. Solution gas drive or gas drive mechanisms. For example, steam+CO2 was evaluated by Balog (1982) for a CSS process, using a mathematical simulation model. Compared to steam, steam+CO2 (about 9% (v/v) CO2) improved productivity by 35 to 38%, efficiency (OSR) by 49 to 57% and showed considerable CO2 retention in the reservoir—about 1.8 MSCF/bbl. heavy oil after 3 CSS cycles.
There have only been a few studies of steam+O2. Combustion tube tests have been performed using mixtures of steam and oxygen (Moore (1994)(1999)). The results have been positive, showing good HTO combustion, even for very low oxygen concentrations in the mixture (FIG. 28). The combustion was stable and more complete than other oxidant mixes (FIG. 29). Oxygen concentrations in the mix varied from just under 3% (v/v) to over 12% (v/v).
Yang ((2008) (2009(1)) proposed to use steam+oxygen as an alternative to steam in a SAGD process. The process was simulated using a modified STARS simulation model, incorporating combustion kinetics. Yang demonstrated that for all oxygen mixes, the combustion zone was contained in the gas/steam chamber, using residual bitumen as a fuel and the combustion front never intersected the steam chamber walls. FIG. 30 shows production forecasts using steam+oxygen mixtures varying from 0 to 80% (v/v) oxygen. But, the steam/gas chamber was contained with no provision to remove non-condensable gases. So, back pressure in the gas chamber inhibited gas injection and bitumen production, using steam+oxygen mixtures, was worse than steam-only (SAGD) performance (FIG. 30). Also, there was no consideration of the corrosion issue for steam+oxygen injection into a horizontal well, nor was there any consideration of minimum oxygen flux rates to initiate and sustain HTO combustion using a long horizontal well for O2 injection.
Yang ((2008), 2009(1)) also proposed an alternating steam/oxygen process as an alternative to continuous injection of steam+O2 mixes. But, issues of corrosion, minimum oxygen flux maintenance, ignition risks and combustion stability, were not addressed.
Bousard (1976) proposed to inject air or oxygen with hot water or steam to propogate LTO combustion as a method to inject heat into a heavy oil reservoir. But HTO is desirable and LTO is undesirable, as discussed above.
Pfefferle (2008) suggested using oxygen+steam mixtures in a SAGD process, as a way to reduce steam demands and to partially upgrade heavy oil. Combustion was purported to occur at the bitumen interface (the chamber wall) and combustion temperature was controlled by adjusting oxygen concentrations. But, as shown by Yang, combustion will not occur at the chamber walls. It will occur inside the steam chamber, using coke produced from residual bitumen as a fuel not bitumen from/at the chamber wall. Also, combustion temperature is almost independent of oxygen concentration (Butler, 1991). It is dependant on fuel (coke) lay down rates by the combustion/pyrolysis process. Pfefferle also suggested oxygen injection over the full length of a horizontal well and did not address the issues of corrosion, nor of maintaining minimum oxygen flux rates if a long horizontal well is used for injection.
Pfefferle, W. C. “Method for CAGD Recovery of Heavy Oil” US Pat. 2007/0187094 A1, Aug. 16, 2007 describes—a process similar to SAGD to recover heavy oil, using a steam chamber. There are 2 versions described. The first version, injects a steam+oxygen mixture using a SAGD steam injector well. The second version injects oxygen into a new horizontal well, parallel to the SAGD well pair, but completed in the upper part of the reservoir. With the separate oxygen injector, steam is injected into the reservoir from the upper SAGD well to limit access of oxygen to the lower SAGD producer, Pfefferle(2007) proposes combustion occurs at the chamber walls (i.e. the steam—cold bitumen interface) and that temperature of combustion can be controlled by changing oxygen concentrations. It is proposed to increase combustion temperatures at the chamber walls sufficiently to crack and upgrade the oil.
But Pfefferle (2007)
(1) doesn't focus on bitumen but uses the term oil or heavy oil.
(2) there is no provision to remove non-condensable gases produced by combustion
(3) except for the second version of the process, oxygen and steam are not segregated to control/minimize corrosion
(4) there is no consideration for a preferred range of oxygen/steam ratios or oxygen concentrations
(5) in both cases oxygen injection is spread out over a long horizontal well. In the first case oxygen is also diluted with steam. There is no consideration to limiting oxygen-reservoir contact to ensure and control oxygen flux rates.
Pfefferle(2007) alleges that combustion will occur at the steam chamber wall (claims 1, 2, 7, 9). In reality this will never occur. Combustion will always occur in the steam-swept zone, using a coke fraction of residual bitumen as a fuel. Even without steam injected, a steam-swept zone will be formed using connate water from the reservoir. The combustion zone will always be far away from the steam chamber walls.
Pfefferle (2007) also alleges that the combustion temperature can be adjusted by changing the oxygen concentration (claims 2, 7, 9). This is not possible. Combustion temperature is controlled by the coke concentration in the matrix where combustion occurs. This has been confirmed by lab combustion tube tests. Combustion temperatures are substantially independent of oxygen concentration at the combustion site.
Finally Pfefferle(2007) also alleges that temperature at the chamber walls can be controlled by oxygen concentration (claims 7, 9) even to the extent of cracking and upgrading oil at the walls. In view of the discussion above, this will not happen.
Pfefferle, W. C. “Method for In Situ Combustion of In-Place Oils”, U.S. Pat. No. 7,581,587 B2, Sep. 1, 2009 describes a geometry for dry in situ combustion using a vertical well and a horizontal production well. The vertical well has a dual completion and is located near the heel of the production well. The lower completion in the vertical well is near the horizontal producer and is used to inject air for ISC. The concentric upper completion is near the top of the reservoir and is used to remove non-condensable gases produced by combustion. Production is adjusted so the lower horizontal well is full of liquids (oil+water) at all times. The bleed well (gas removal well) may also have a horizontal section. Multiple bleed wells are also proposed. This is a heel-to-toe process. Most ISC processes using horizontal producers (eg THAI) are toe-to-heel processes. This process is for dry ISC and really doesn't apply to SAGDOX except, perhaps, for well configurations.
None of the SAGDOX versions described herein are for heel-to-toe processes. SAGDOX always has steam injection. Pfefferle doesn't discuss steam as an additive or as an option.
There exists therefore a long felt need to provide an effective SAGDOX process which is energy efficient and can be utilized to recover bitumen from a reservoir over a number of years until the reservoir is depleted.
It is therefore a primary object of the invention to provide a SAGDOX process wherein oxygen and steam are injected separately into a bitumen reservoir.
It is a further object of the invention to provide at least one well to vent produced gases from the reservoir to control reservoir pressures.
It is yet a further object of the invention to provide production wells extending a distance of greater than 1000 meters.
It is yet a further object of the invention to provide oxygen at an amount of substantially 35% (v/v) and corresponding steam levels at 65%.
It is yet a further object of the invention to provide oxygen and steam from a local cogeneration and air separation unit located proximate a SAGDOX process.
Further and other objects of the invention will be apparent to one skilled in the art when considering the following summary of the invention and the more detailed description of the preferred embodiments illustrated herein.